Methods and systems of variable extraction for compressor protection

ABSTRACT

A method of protecting a turbine compressor of a gas turbine engine that is part of an integrated gasification combined-cycle power generation system that includes an air separation unit that may include the steps of: (1) extracting an amount of compressed air that is compressed by the turbine compressor; (2) supplying the extracted amount of compressed air to the air separation unit; and (3) varying the amount of compressed air extracted from the turbine compressor based upon a desired compressor pressure ratio across the turbine compressor. The method further may include the step of supplying the air separation unit with a supply of compressed air from a main air compressor. The amount of compressed air supplied to the air separation unit by the main air compressor may be varied based upon the amount of compressed air extracted from the turbine compressor.

TECHNICAL FIELD

This present application relates generally to methods for protecting acompressor in a gas turbine engine. More specifically, but not by way oflimitation, the present application relates to methods for protecting acompressor in a gas turbine engine that is part of a integratedgasification combined-cycle power generation system by varying theamount of compressed air extracted from the compressor and supplied tothe plant for process uses.

BACKGROUND OF THE INVENTION

In current integrated gasification combined-cycle (“IGCC”) powergeneration systems, an air separation unit is used to supply O₂ to agasifier, which then generates partially combusted gases for use as fuelin a gas turbine. Compressed air is generally supplied to the airseparation unit from both a main air compressor and/or throughextraction from the discharge of the gas turbine compressor. Currently,the amount of compressed air extracted from the turbine compressordischarge is approximated a fixed percentage of compressor flow and isbased only on the needs of the external demand of the air separationunit.

In such systems, the goal for the operation of the gas turbine is tosatisfy desired load levels while maximizing efficiency. This includesallowing the gas turbine unit to operate at a desired maximum level loadacross changing ambient conditions without exceeding the maximum loadlevel, while also respecting the operational boundaries of the turbine.Operational boundaries, for example, include maximum allowabletemperatures within the turbine or combustor components. Exceeding thesetemperatures may cause damage to turbine components or cause increasedemissions levels. Another operational boundary includes a maximumcompressor pressure ratio or compressor margin. Exceeding thislimitation may cause the unit to surge or stall, which may result inextensive damage to the compressor. Further, the turbine may have amaximum mach number, which indicates the maximum flow rate of thecombusted gases as the gases exit the turbine. Exceeding this maximumflow rate may damage turbine components.

Accordingly, controlling the operation of the gas turbine to improveefficiency while satisfying the operational limitations or requirementsis a significant goal within the industry. Several known methods areused by turbine operators to control or limit the load of the turbinewhile these satisfying operational boundaries. These known methodsinclude manipulating inlet bleed heat, the inlet guide vanes of thecompressor, and/or turbine fuel supply.

Inlet bleed heat allows a turbine operator to bleed the discharge air ofthe turbine compressor and recirculate the bleed air back to thecompressor inlet. Because some of the compressor flow is recycled to theinlet, this method reduces the amount of flow through the compressorthat expands through the turbine, which reduces the Output of theturbine. This method of gas turbine load control also may raise theinlet temperature of the compressor inlet air by mixing the colderambient air with the bleed portion of the hot compressor discharge air.This rise in temperature reduces the air density and, thus, the massflow across the compressor to the gas turbine. Although this approachmay be used to allow the gas turbine unit to operate at a maximum levelloaded across changing ambient conditions (while respecting operationalboundaries such as maximum compressor pressure ratio), it comes with acost, as it reduces the thermal efficiency of the gas turbine.

Closure of the inlet guide vanes, which control the flow of air to theturbine compressor, is another common method of decreasing the mass flowacross the gas turbine, which, in turn, may be used to control or limitturbine load. Closing the inlet guide vanes may restrict the passage ofair to the compressor and, thus, decreases the amount of air enteringthe compressor. This approach also may be used to allow the gas turbineunit to operate at a maximum level load across changing ambientconditions (while respecting operational boundaries such as maximumcompressor pressure ratio or compressor margin), but it also reduces thethermal efficiency of the gas turbine by operating the compressor awayfrom its optimum design point.

Finally, the turbine load may be controlled or limited by decreasing theflow of fuel to the combustor. This will decrease the combustiontemperature of the turbine and the output of the gas turbine engine. Inthe case of falling ambient temperatures, such a measure may allow theturbine to maintain a maximum level load (while respecting operationalboundaries such as maximum compressor pressure ratio or compressormargin). However, as is known in the art, the reduction in combustiontemperature decreases the efficiency of the gas turbine engine.

These known methods of controlling turbine operation adversely affectthe efficiency of the gas turbine engine. Further, none of these controlmethods take advantage of the specific components that are part of anIGCC power generation system to allow the system to operate moreefficiently. Thus, there is a need for a more efficient method forprotecting a compressor in a gas turbine engine that are part of aintegrated gasification combined-cycle power generation system.

SUMMARY OF THE INVENTION

The present application thus may describe a method of protecting aturbine compressor of a gas turbine engine that is part of an integratedGasification combined-cycle power generation system that includes an airseparation unit that may include the steps of (1) extracting an amountof compressed air that is compressed by the turbine compressor; (2)supplying the extracted amount of compressed air to the air separationunit; and (3) varying the amount of compressed air extracted from theturbine compressor based upon a desired compressor pressure ratio acrossthe turbine compressor. The method further may include the step ofsupplying the air separation unit with a supply of compressed air from amain air compressor. The amount of compressed air supplied to the airseparation unit by the main air compressor may be varied based upon theamount of compressed air extracted from the turbine compressor.

A combined supply of compressed air may include the amount of compressedair supplied to the air separation unit by the main air compressor andthe amount of compressed air extracted from the turbine compressor. Thiscombined supply of compressed air may include a supply of compressed airthat satisfies the total supply of compressed air required by the airseparation unit.

In some embodiments, the step of varying the amount of compressed airsupplied to the air separation unit by the main air compressor basedupon the amount of compressed air extracted from the turbine compressormay include the step of decreasing the amount of compressed air suppliedto the air separation unit by the main air compressor when the amount ofcompressed air extracted from the turbine compressor is increased. Theamount by which the compressed air supplied to the air separation unitby the main air compressor is decreased may be approximately the same asthe amount by which the amount of compressed air extracted from theturbine compressor is increased. The step of varying the amount ofcompressed air supplied to the air separation unit by the main aircompressor based upon the amount of compressed air extracted from theturbine compressor may include the step of increasing the amount ofcompressed air supplied to the air separation unit by the main aircompressor when the amount of compressed air extracted from the turbinecompressor is decreased. The amount by which the compressed air suppliedto the air separation unit by the main air compressor is increased maybe approximately the same as the amount by which the amount ofcompressed air extracted from the turbine compressor is decreased.

In some embodiments, the step of varying the amount of compressed airextracted from the turbine compressor based upon the desired compressorpressure ratio may include the steps of: (1) measuring the pressure atthe inlet and exit of the turbine compressor; (2) determining an actualcompressor pressure from the pressure measurements taken at the inletand exit of the turbine compressor; and (3) comparing the actualcompressor pressure ratio to the desired compressor ratio. The desiredcompressor pressure ratio may be a compressor pressure ratio that eitherdoes not cause the turbine compressor to surge or violate a desiredminimum compressor margin.

Some embodiments may include the step of increasing the amount ofcompressed air extracted from the turbine compressor if the actualcompressor pressure ratio is measured to greater than the desiredcompressor pressure ratio. Some embodiments may include the step ofdecreasing the amount of compressed air extracted from the turbinecompressor if the actual compressor pressure ratio is measured to beless than the desired compressor pressure ratio.

The present application thus may describe a system for protecting aturbine compressor of a gas turbine engine that is part of an integratedgasification combined-cycle power generation system that includes an airseparation unit. The systems may include a turbine compressor thatcompresses air; means for extracting an amount of compressed air fromthe turbine compressor and means for supplying the extracted amount ofcompressed air to the air separation unit; and means for varying theamount of compressed air extracted from the turbine compressor basedupon a desired compressor pressure ratio across the turbine compressor.

In some embodiments, the system may include means for determining theactual compressor pressure ratio across the turbine compressor. Adesired compressor pressure ratio across the turbine compressor may be acompressor pressure ratio that either does not cause the turbinecompressor to surge or violate a desired minimum compressor margin. Themeans for varying the amount of compressed air extracted from theturbine compressor based upon a desired compressor pressure ratio acrossthe turbine compressor may include means for comparing the actualcompressor pressure ratio across the turbine compressor to the desiredcompressor pressure ratio across the turbine compressor and means forvarying the amount of compressed air extracted from the turbinecompressor based on the comparison of the compressor pressure ratioacross the turbine compressor against the desired compressor pressureratio across the turbine compressor.

In some embodiments, the amount of compressed air extracted from theturbine compressor may be increased if the actual compressor pressureratio is measured to greater than the desired compressor pressure ratio.In some embodiments, the amount of compressed air extracted from theturbine compressor may be decreased if the actual compressor pressureratio is measured to be less than the desired compressor pressure ratio.The means for varying the amount of compressed air extracted from theturbine compressor based upon the desired compressor pressure ratioacross the turbine compressor may include aproportional-integral-derivative controller.

In some embodiments, the system may include a main air compressor thatsupplies the air separation unit with a supply of compressed air from amain air compressor and means for varying the amount of compressed airsupplied to the air separation unit by the main air compressor. Theamount of compressed air supplied to the air separation unit by the mainair compressor may be varied based upon the amount of compressed airextracted from the turbine compressor. In some embodiments, the amountof compressed air supplied to the air separation unit by the main aircompressor is increased when the amount of compressed air extracted fromthe turbine compressor is decreased, and the amount of compressed airsupplied to the air separation unit by the main air compressor isdecreased when the amount of compressed air extracted from the turbinecompressor is increased.

These and other features of the present application will become apparentupon review of the following detailed description of the preferredembodiments when taken in conjunction with the drawings and the appendedclaims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic plan of an exemplary turbine that may be used withcertain embodiments of the present application.

FIG. 2 is a schematic plan of an exemplary integrated gasificationcombined-cycle (“IGCC”) power generation system that may be used withcertain embodiments of the present application.

FIGS. 3( a), 3(b) and 3(c) include several related plots thatdemonstrated results from an exemplary IGCC power generation system inwhich the level of extraction of compressed air from the turbinecompressor is varied so that a maximum load for the turbine may beefficiently maintained (while respecting operational boundaries such asmaximum compressor pressure ratio or compressor margin) through changingambient conditions.

FIGS. 4( a) and 4(b) include two plots demonstrating how temperatureinside the combustor 106 may be varied so that a maximum allowabletemperature of the gases exiting the combustor is not exceeded as theturbine 100 operates at a constant load through changing ambientconditions.

FIGS. 5( a) and 5(b) includes two plots demonstrating how the setting ofthe Inlet Guide Vanes may be varied so that a maximum exit mach numberis not exceeded as the turbine 100 operates at a constant load throughchanging ambient conditions.

FIG. 6 is a flow diagram demonstrating an exemplary control process thatmay be used to set the exhaust temperature of the turbine.

FIG. 7 is a flow diagram demonstrating an exemplary control process thatmay be used to calculate a set point for the inlet guide vanes (i.e.,the angle of orientation of the inlet guide vanes) of a turbine.

FIG. 8 is a flow diagram demonstrating an exemplary control process forcalculating the turbine compressor extraction set point (i.e., theamount or percentage of the compressed air from the turbine compressorthat is extracted and supplied to the air separation unit).

DETAILED DESCRIPTION OF THE INVENTION

Referring now to the figures, where the various numbers represent likeparts throughout the several views, FIG. 1 demonstrates a schematicillustration of an exemplary gas turbine engine 100 that may be usedwith certain embodiments of the present application. The gas turbineengine 100 may include a compressor, which also may be known as aturbine compressor 104, a combustor 106, and a turbine 108 connectedserially. The turbine compressor 104 and the turbine 108 may be coupledby a shaft 110, which also may couple the turbine 108 and drive anelectrical generator (not shown). In certain embodiments, the gasturbine engine 100 may be a 7FB engine, which is commercially availablefrom General Electric Company, although the gas turbine engine 100illustrated and described herein is exemplary only. Accordingly, the gasturbine engine 100 is not limited to the gas turbine engine shown inFIG. 1 and described herein, but rather, the gas turbine engine 100 maybe any gas turbine engine. For example, but not by way of limitation, inan alternative embodiment, the gas turbine engine 100 may be amulti-shaft gas turbine engine having two shafts for separately drivingthe electrical generator (not shown) and the turbine compressor 104.

In operation, air (as indicated by arrows 112) may flow into the gasturbine engine 100 through the turbine compressor 104 and may becompressed. Compressed air then may be channeled to the combustor 106where it may be mixed with fuel and ignited. The expanding hot gasesfrom the combustor 106 may drive the rotating turbine 108 and may exit(as indicated by an arrow 113) the gas turbine engine 100 through anexhaust diffuser 114. Additionally, in some embodiments, exhaust gasesfrom the turbine engine 100 may be supplied to a heat recovery steamgenerator (not shown) that generates steam for driving a steam turbine(not shown).

FIG. 2 is a schematic diagram of an exemplary integrated gasificationcombined-cycle (“IGCC”) power generation system 200 that may be usedwith certain embodiments of the present application. Though, those ofordinary skill will appreciate that that the current application is notlimited for use with the IGCC power generation system 200 and that itmay be used with other systems that include a gas turbine engine. TheIGCC power generation system 200 may incorporate the gas turbine engine100 described above. The IGCC system 200 may further include a main aircompressor 202, an air separation unit 204 coupled in flow communicationto the main air compressor 202 and the turbine compressor 104, agasifier 206 coupled in flow communication to the air separation unit204, the combustor 106 coupled in flow communication to the gasifier206, and the turbine 108. The arrows in FIG. 2 indicate flow directions.

In general operation, the main compressor 202, which may include one ormore compressors known in the art, may compress ambient air (the flow ofwhich is indicated by arrows 207). The compressed air from the maincompressor 202 may be channeled to the air separation unit 204.Compressed air from the turbine compressor 104 may be extracted andsupplied to air separation unit 204. The extraction of the compressedair from the turbine compressor 104 may be completed by manifolding thecompressed air from the turbine compressor 104 into a pipe and routingthe extracted compressed air to the air separation unit 204. A valve205, such as a butterfly valve or other similar valve, may be installedin the pipe to control the amount of compressed air that is extractedfrom the turbine compressor 104. Those of ordinary skill in the art willappreciated that other methods and systems may be used to extract anamount of compressed air from the turbine compressor 104 and deliver itto the air separation unit 204. The air separation unit 204, thus, mayreceive the supply of compressed air necessary for its function from themain compressor 202 and from the compressed air extracted from theturbine compressor 104.

The air separation unit 204 then may use the supply of compressed air togenerate oxygen for use by the gasifier 206 pursuant to methods known inthe art. More specifically, the air separation unit 204 may separate thecompressed air into separate flows of oxygen (the flow of which isrepresented by a pathway 208) and a gas by-product, sometimes referredto as a “process gas.” The process gas generated by the air separationunit 204 may include nitrogen and will be referred to herein as“nitrogen process gas.” The nitrogen process gas also may include othergases, such as oxygen, argon, etc. In some embodiments, the nitrogenprocess gas may include between about 95% and about 100% nitrogen.

The oxygen flow from the air separation unit 204 may be channeled to thegasifier 206 for use in generating partially combusted gases, referredto herein as “syngas,” for use by the gas turbine engine 100 as fuel. Insome known IGCC systems, at least some of the nitrogen process gas flow,a by-product of the air separation unit 204, may be vented to theatmosphere (the flow of which is represented by a pathway 210). In someknown IGCC systems, some of other nitrogen process gas flow (the flow ofwhich is represented by a pathway 211) may be supplied to a nitrogenboost compressor 208 and then fed into the combustor 106 to facilitatecontrolling emissions of the turbine 108.

The gasifier 206 may convert a mixture of fuel (the flow of which isrepresented by pathway 212), the oxygen supplied by the air separationunit 204 (the flow of which is represented by the pathway 208), steam(the flow of which is represented by pathway 213), and/or limestone (theflow of which is not shown) into an output of syngas for use by the gasturbine engine 100 as fuel pursuant to methods known in the art.Although the gasifier 206 may use many types of fuel, in some known IGCCsystems, the gasifier 206 may use pulverized coal, petroleum coke,residual oil, oil emulsions, tarsands, and/or other similar fuels. Insome known IGCC systems, the syngas generated by the gasifier 206 mayinclude carbon dioxide, sulfur or other undesired contaminants. Thesyngas generated by the gasifier 206 (the flow of which is representedby pathway 214) may be cleaned by a clean-up device 216, which also maybe known as a acid removal system, to remove some or all of thesecontaminants before being channeled to the combustor 106 for combustionthereof.

The power output from the gas turbine engine 100 may drive theelectrical generator (not shown) that supplies electrical power to apower grid (not shown). Exhaust gas from the has turbine engine 100 maybe supplied to a heat recovery steam generator (not shown) thatgenerates steam for driving steam turbine (not shown). Power generatedby steam turbine may drive an electrical generator (not shown) thatprovides electrical power to the power grid. In some known IGCC systems,steam from a heat recovery steam generator also may be supplied togasifier 206 for generating the syngas.

As part of the embodiments of the present application, the amount ofcompressed air extracted from the turbine compressor 104 and supplied tothe air separation unit 204 may be varied as a means of controlling theload of the turbine 100 in the IGCC power system 200 and/or meeting theoperability limits of the turbine 100. For example, FIG. 3 demonstratesthe exemplary results of such turbine 100 control and operation. FIG. 3includes several related plots that demonstrate exemplary operation ofthe gas turbine engine 100 in which the level of extraction ofcompressed air from the turbine compressor is varied so that a maximumload and operability limits for the turbine may be efficientlymaintained (and not exceeded) through changing ambient conditions.

FIG. 3( a) demonstrates exemplary results showing extraction percentage(i.e., the percentage of the compressed air from the turbine compressor104 that is extracted and supplied to the air separation unit 204)versus ambient temperature.

FIG. 3( b) demonstrates exemplary results showing compressor marginversus ambient temperature as the extraction percentage is varied. Thecompressor margin may reflect the differential between the measuredpressure ratio of the turbine compressor 104 and the maximum pressureratio at which the turbine compressor 104 may operate at a given flowrate and speed without the turbine compressor 104 experiencing surge.Compressor pressure ratio may reflect the ratio between the pressure atthe discharge and inlet of the turbine compressor 104. Surge is a stallcondition that may occur in the turbine compressor 104 at a certaincompressor pressure ratio for a given flow rate through the turbinecompressor 104 at a given turbine compressor 104 speed (i.e., rpm). Asdescribed, surge may cause extreme damage to the turbine compressor 104.A minimum compressor operating limit line 302 may reflect the minimumacceptable compressor margin allowed by the system operator (i.e., anoperational off-set) during operation of gas turbine engine 100.

FIG. 3( c) demonstrates exemplary results showing turbine output (i.e.,load) versus ambient temperature as the extraction percentage is varied.A maximum base load level line 303 may reflect the maximum allowableload for the turbine 100.

As demonstrated in FIGS. 3( a), 3(b) and 3(c), the extraction percentagemay be increased as the ambient temperature decreases so that themaximum baseload level and other operability limits, such as thecompressor margin, for the turbine 100 are not violated. Note that thefollowing described graphs contain data that is exemplary only and ismeant only to demonstrate general gas turbine operation using themethods and systems of the current application. The points, ranges anddata associated with these graphs may be substantially vary fordifferent systems under alternative conditions. As shown in FIG. 3( a),at an ambient temperature of about 70° F. (21° C.), the extractionpercentage may be approximately 5% (point 304). As the ambienttemperature falls to about 50° F. (10° C.), the extraction percentagemay be increased to approximately 7% (point 306). As demonstrated inFIG. 3( b), the compressor margin at about 70° F. (21° C.) and at anextraction percentage of approximately 5% is approximately 0.30 (point308). The compressor margin at about 50° F. (10° C.) and at anextraction percentage of approximately 7% is approximately 0.45 (point310). FIG. 3( c) demonstrates that at both 70° F. (21° C.) (point 312)and 50° F. (10° C.) (point 314) the maximum baseload level may bemaintained through the changing ambient conditions (i.e., the load ofthe turbine 100 remains at the maximum baseload level line 303 as thetemperature falls from 70° to 50° F. (21° to 10° C.)).

The results shown in FIGS. 3( a), 3(b) and 3(c) demonstrate several ofthe operational benefits to varying the amount of compressed airextracted from the turbine compressor 104. First, variable extraction ofthe compressed air from the turbine compressor may provide an additionalcontrol variable that allows for operational boundaries to be respectedduring turbine 100 operation. As shown in the FIG. 3 example discussedabove, the ambient temperature decreases from 70° to 50° F. (21° to 10°C.), yet the maximum baseload level (points 312 and 314) may bemaintained and an acceptable compressor margin may be maintained (thelevel actually increases from 0.30 to 0.45, see points 308 and 310).Further, variable extraction may allow the turbine 100 to maintain themaximum baseload level through changing ambient conditions. As is knownin the art, assuming other operational factors remain constant, areduction in ambient temperature results in an increase in turbineoutput. Thus, to take the above FIG. 3 example further, if the ambienttemperature decreases from 70° to 50° F. (21° to 10° C.) when theturbine 10 already is functioning at maximum baseload level the turbineoperator would have to begin certain control measures in order for theturbine 100 to maintain (and not exceed) the maximum baseload level. Asknown in the art, these control measures may include bleeding inlet heat(i.e., bleeding off the discharge air of the turbine compressor 104 andrecirculating the bleed air back to the compressor inlet), closing theinlet guide vanes, and/or reducing turbine fuel supply (i.e., reducingturbine inlet temperature). As discussed, however, such control measuresreduce the thermal efficiency of the gas turbine 100 and are not asefficient as increasing the extraction percentage from the turbinecompressor 104. FIGS. 3( a), 3(b) and 3(c) demonstrate that varying theextraction level may successfully prevent the gas turbine 100 fromexceeding its maximum baseload level while satisfying its operabilitylimits, such as the compressor margin, through changing ambientconditions.

Second, an increase in the supply of compressed air that is extractedfrom the turbine compressor 104 may decrease in an equivalent quantitythe amount of compressed air needed from the main compressor 202 tosupply the air separation unit 204 with the necessary amount ofcompressed air. This may result in decreased usage of the maincompressor 202, which may increase the overall efficiency of the systemby reducing the energy consumption of this component. Further, reducedusage of the main compressor 202 may reduce the maintenance costassociated therewith. As such, unlike the other known methods ofcontrolling the load and maintaining operability limits of the turbine100, varying the extraction level of compressed air to the airseparation unit 204 makes efficient use of the control measure byincreasing the supply of compressed air supplied to the air separationunit 204 from the turbine compressor 104 (i.e., it lessens the outputrequirement of the main compressor 202 and decreases the energyconsumption of that component).

If, on the other hand, the extraction percentage from the turbinecompressor 104 had remained constant in the above discussed example(i.e., at the approximate 4% level of 70° F. (21° C.) as the ambienttemperature decreased to 50° F. (10° C.), the operator of the turbine100 would have been required to begin such actions as inlet bleed heat,closing the inlet guide vanes, and/or reducing turbine fuel supply inorder to limit turbine load and respect other operability limits, suchas the compressor margin. Further, the overall system would be requiredto make up the difference in the amount of compressed air extracted fromthe turbine compressor 104 between the 4% and the 7% extraction levelwith the main compressor 202, which would further decrease theefficiency of the overall system.

As demonstrated in FIGS. 3( a), 3(b) and 3(c), generally, the percentextracted may be decreased as the ambient temperature rises so that theturbine output at the maximum baseload level line 303 is maintained(i.e., if the percent extracted was not reduced and other operationalfactors remained the same, turbine output would fall as the ambienttemperature rises). At some point as the ambient temperature continuesto rise, the turbine 100 may no longer be able to satisfy the loadrequirement of the maximum baseload level line 303 while also respectingoperation boundaries (such as the compressor operating limit line 302)even if the percentage of extracted compressed air were further reduced.In FIG. 3, this occurs at approximately 80° F. (27° C.), though it mayoccur at other temperatures for different systems under differentconditions. At such a point, extraction percentage may no longer bereduced so that maximum baseload level line 303 may be maintainedwithout violating the minimum compressor margin line 302. After thispoint, turbine load may be reduced by other means and/or extractioncontinued so that system efficiency is maximized at a turbine outputlevel below the maximum baseload level line 303. Up until this point,turbine output (i.e., load) is controlled at a maximum desired level,while respecting other operability limits, such as the compressormargin, through changing ambient conditions in a manner that maximizessystem efficiency.

FIGS. 4( a) and 4(b) include two plots demonstrating how temperatureinside the combustor 106 may be varied so that a maximum allowabletemperature of the gases exiting the combustor is not exceeded as theturbine 100 operates at a constant load through changing ambientconditions. In these plots, “Tfire” represents the temperature of thegases exiting the first stage nozzle within the combustor 106 and “T3.9”represents the temperature of the gases exiting the combustor 106. Asshown, as the ambient temperature decreases, Tfire may be decreased sothat the maximum allowable T3.9 temperature, which is represented by aMaximum 13.9 Line 402, is not exceeded. Initially, when the ambienttemperature is decreasing from about 100° to 60° F. (38° to 16° C.),Tfire may be maintained at a level that corresponds to a maximumallowable Tfire temperature, which is represented by a Maximum TfireLine 404. Also, as the ambient temperature decreases from 100° to 60° F.(38° to 16° C.), the 13.9 temperature may increase until it reaches theMaximum T3.9 Line at a point 406. As the ambient temperature decreasesbeyond 60° F. (16° C.) and, as stated, while a Constant load ismaintained), Tfire may be reduced so that the Maximum T3.9 Line 402 isnot violated. For example, at an ambient temperature of 40° F. (4° C.),Tfire may be reduced to a level below the Maximum Tfire Line 404 (point408) so that the T3.9 temperature does not exceed the Maximum T3.9 Line402 (point 410).

Variable extraction (i.e., varying the amount of compressed airextracted from turbine compressor 104 for supply to the air separationunit 204) may be used to ensure that operational limits, such as MaximumT3.9 Line 402 and the Maximum Tfire Line 404, are observed and systemefficiency is maximized. For example, if decreasing fuel flow is used asthe primary control for limiting turbine load level, the temperaturesfor Tfire and T3.9 are not maximized to their respective limits. On theother hand, varying extraction to maintain maximum Tfire/T3.9temperatures is more efficient because of the direct relationshipbetween high system temperatures and increased system efficiency. Thus,extraction may be increased during falling ambient temperatures suchthat maximum Tfire/T3.9 temperatures may be maintained while maximumload level are not exceeded.

FIGS. 5( a) and (b) include two plots demonstrating how the setting ofthe Inlet Guide Vanes may be varied so that a maximum velocity of thefluid exiting the turbine 100 is not exceeded as the turbine 100operates at a constant load through changing ambient conditions. In thisplot, “IGV” refers to the setting (i.e., angle of orientation) of theinlet guide vanes and “Axial Exit MN” refers the velocity of the fluidas it exits the turbine 100, which also is known as the turbine machnumber. As shown, as the ambient temperature decreases beyond about 80°F. (27° C.), the angle of orientation of the inlet guide vanes may bereduced (i.e., the inlet guide vanes are further “closed”) so that amaximum allowable exit fluid velocity, which is represented by a MaximumMach Number Line 502, is not exceeded. For example, from 60° to 40° F.(16° to 4° C.), the IGV angle of orientation is reduced fromapproximately 83° (see point 504) to 81° (see point 506) such that theexit fluid velocity is maintained at or below the Maximum Mach NumberLine 502 (see points 508 and 510).

Variable extraction may be used to ensure that operational limits, suchas the Maximum Mach Number Line 502, are observed, while maximizingsystem efficiency beyond that of which the other known control means,such as manipulating the setting of the Inlet Guide Vanes, are capable.For example, increasing the percentage of compressed air extracted fromthe turbine compressor 104 may decrease the amount of compressor flowthat is available to expand through the turbine 104, which, in turn,will decrease the velocity of the fluid as it exits the turbine. Assuch, when ambient temperatures are falling, the need to decrease airflow to the turbine compressor 104 through inlet guide vane manipulationmay be decreased by varying (in this case, increasing) the level ofextraction from the turbine compressor 104. As already discussed,varying extraction to maintain operational limits, such as the maximumallowable velocity of the fluid as it exits the turbine 100, is moreefficient than closure of the inlet guide vanes because, among otherthings, the increased amount of extracted air may be supplied to airseparation unit 204 so that the demand on the main air compressor 202 isdecreased and overall system efficiency is increased.

Therefore, during the operation of the IGCC power generation system 200,the amount of compressed air extracted from turbine compressor 104 forsupply to the air separation unit 204 may be varied to control the loadon turbine 100 and ensure that the operational boundaries of turbine 100are maintained such that system efficiencies are maximized. Further, anincreased supply of extracted compressed air from turbine compressor 104may reduce the energy consumption of main air compressor 202 such thatthe overall efficiency of the IGCC system 200 is enhanced. This methodof turbine 100 control may be accomplished in several ways, including,but not by limitation, the control processes demonstrated in FIGS. 6-8.

FIG. 6 is a flow diagram demonstrating an exemplary control process thatmay be used to set the exhaust temperature (“Texh”) of the turbine 100.At block 602, a compressor pressure ratio measurement may be takenacross turbine compressor 104. At 604, the compressor pressure ratiomeasurement may be used to calculate Texh for a part load condition(i.e., an operating condition that is less than approximately 96% ofbaseload). The calculated part load Texh then may be forwarded to a“minimum select” block 606 depending on the state of a switch 608. If itis determined that the turbine 100 is operating in a part loadcondition, the switch 608 may be closed, allowing the calculated partload Texh to pass through to the minimum select block 606. If, on theother hand, it is determined that the turbine 100 is not operating in apart load condition, the switch 606 may reside in the open condition sothat the calculated part load Texh is not forwarded to the minimumselect block 606.

At a block 610, another Texh set point calculation may be completedbased upon the measured compressor pressure ratio 602 and a knowncombustor exit temperature limit 612, which represents the maximumallowable exit temperature for the combustor 106. The calculated Texhfrom block 610 then may be input in the minimum select block 606. Theminimum select block 606 then function to select the minimum Texh setpoint from the two inputs. i.e., between the inputs from block 604(assuming switch 608 is in the closed position) and block 610.

A second minimum select, a minimum select block 613, may select theminimum calculated Texh set point from the inputs supplied to it by theminimum select block 606 and the input from a block 614. At block 614, aTexh set point calculation may be made based upon the compressor ratiomeasured at block 602 and a known turbine inlet temperature maximum 616(i.e., the maximum temperature allowed at the turbine inlet). Theminimum of these two inputs into minimum select block 613 may beselected and the result may become a Texh set point 618.

FIG. 7 is a flow diagram demonstrating an exemplary control process thatmay be used to calculate a set point for the inlet guide vanes, whichmay determine the angle of orientation of the inlet guide vanes of theturbine 100. At a block 702, a target turbine exhaust flow rate may becalculated based upon a measured valued of the Texh 704, a measuredvalue of the pressure of the turbine exhaust 706, and a known maximumallowable turbine exhaust flow rate 707. The target turbine exhaust flowrate that is calculated at block 702 then may be input into a block 708along with the following: a measured ambient temperature 710, a measuredambient air pressure 712, and a measured fuel flow rate 714. With thisinformation, a target inlet guide vane set point may be calculated permethods known in the art.

The value calculated at block 708 then may be input into a minimumselect block 716. Minimum select block 716 may select the inlet guidevane set point value from the following: 1) the inlet guide vane setpoint calculated at block 708; a part load inlet guide vane set pointcalculated by methods known in the art 718; and a known maximumallowable inlet guide vane set point 720. The determined minimum atminimum select block 716 is then selected as an inlet guide vane setpoint 722.

FIG. 8 is a flow diagram demonstrating an exemplary control process forcalculating the turbine compressor 104 extraction set point (i.e., theamount or percentage of the compressed air from the turbine compressor104 that is extracted and supplied to the air separation unit 204). Atblock 802, a differential may be calculated between a measured turbineload 804 and a target turbine load 806. The turbine load may be measuredby devices and systems known in the art, including a precision poweranalyzer, a watt-hour meter or other similar devices and systems. Themeasured turbine load 804 may be compared to the target turbine load 806(and a differential calculated) by devices, controllers and systemsknown by those of ordinary skill in the art, including a programmablelogic controller or other similar devices, controllers and systems. Thecalculated differential then may be inputted into aproportional-integral-derivative (“PID”) controller or other similardevice at a block 808, and an extraction set point, i.e., the amount ofcompressed air that should be extracted from the turbine compressor 104,may be calculated based on the differential. The calculated extractionset point from block 808 then may be inputted into a maximum selectblock 812. The maximum select block 812 may operate to select themaximum value from multiple entries.

At a block 814, an actual compressor surge margin may be calculatedbased on current operational measurements of turbine compressor 104,including an ambient temperature input 816, a compressor pressure ratioinput 818, a flow rate across the compressor input 820, a measuredcompressor speed 821, etc. Those of ordinary skill will appreciate thatcalculation of the actual compressor surge margin may be completed indifferent manners. At a block 822, a differential may be calculatedbetween the actual compressor margin (calculated at block 814) and adesired minimum compressor margin operating limit (which previously wasreferred to in text related to FIG. 3( b) as the minimum compressoroperating limit line 302). This calculation may be completed by devices,controllers and systems known by those of ordinary skill in the art,including a programmable logic controller or other similar devices,controllers and systems. The calculated differential then may beinputted into a proportional-integral-derivative (“PID”) controller orother similar device at a block 824, and an extraction set point, i.e.,the amount of compressed air that should be extracted from the turbinecompressor 104, may be calculated based on the differential.

The calculated extraction set point from block 824 then may be inputtedinto the maximum select block 812. The maximum select block 812 then mayselected the maximum extraction set point between the extraction setpoint inputs from blocks 808 and 824, which may be referred to as aselected extraction set point 826. The selected extraction set point 826then may be used to set valves, such as a butterfly valve, or othersimilar devices within the turbine compressor 104 or the piping betweenthe turbine compressor 104 and the air separation unit 204. Such that adesired amount of compressed air is extracted from the turbinecompressor 104. The compressed air that is extracted from the turbinecompressor 104 then may be supplied to the air separation unit 204 viapiping and valves, as previously described.

The overall process of extracting a variable amount of compressed airfrom the turbine compressor 104 and supplying the extracted compressedair to the air separation unit 204 to control turbine load, as describedabove, may be implemented and controlled by a computerized plantoperating systems that are known by those of ordinary skill in the art.The operating systems may comprise any appropriate high-poweredsolid-state switching device. The operating system may be a computer;however, this is merely exemplary of an appropriate high-powered controlsystem, which is within the scope of the application. For example, butnot by way of limitation, the operating system may include at least oneof a silicon controlled rectifier (SCR), a thyristor, MOS-controlledthyristor (MCT) and an insulated gate bipolar transistor. The operatingsystem also may be implemented as a single special purpose integratedcircuit, such as ASIC, having a main or central processor section foroverall, system-level control, and separate sections dedicatedperforming various different specific combinations, functions and otherprocesses under control of the central processor section. It will beappreciated by those skilled in the art that the operating system alsomay be implemented using a variety of separate dedicated or programmableintegrated or other electronic circuits or devices, such as hardwiredelectronic or logic circuits including discrete element circuits orprogrammable logic devices, such as PLDs, PALs, PLAs or the like. Theoperating system also may be implemented using a suitably programmedgeneral-purpose computer, such as a microprocessor or microcontrol, orother processor device, such as a CPU or MPU, either alone or inconjunction with one or more peripheral data and signal processingdevices. In general, any device or similar devices on which a finitestate machine capable of implementing the logic flow diagram 200 may beused as the operating system. As shown a distributed processingarchitecture may be preferred for maximum data/signal processingcapability and speed. As would be appreciated by those skilled in theart, the operating system further may control the operation (i.e., theopening, closing or other settings) of the valves and the othermechanical systems of the IGCC power generation system 200 and receiveinput from sensors relaying information concerning system performance(i.e., measurements of current compressor pressure ratio, flow rate,speed, etc.) that may be relevant to the control of the system.

In general terms, the amount of compressed air extracted from theturbine compressor 104 may be varied such that operational boundaries,such compressor margin, are satisfied and system efficiency ismaximized. The compressor margin may reflect the differential betweenthe measured pressure ratio of the turbine compressor 104 and themaximum pressure ratio at which the turbine compressor 104 may operateat a given flow rate and speed without the turbine compressor 104experiencing surge. Varying extraction from the turbine compressor 104may affect the pressure of the discharge of the turbine compressor 104and, thus, the compressor pressure ratio. That is, increasing extractionmay reduce the pressure of the discharge of the turbine compressor 104,which may reduce the compressor pressure ratio, and decreasingextraction may increase the pressure of the discharge of the turbinecompressor 104, which may increase the compressor pressure ratio. Thus,extraction may be varied based on a current measurement of thecompressor pressure ratio, flow rate, and speed, such that the turbinecompressor 104 operates efficiently near, but does not exceed, acompressor pressure ratio that either (1) may cause a surge incident or(2) results in a compressor margin that violates the minimum compressoroperating limit line 302. Further, if the amount of compressed airextracted from the turbine compressor 104 is increased, the supply ofcompressed air furnished by the main air compressor 202 may be decreasedby approximately the same amount (so that the combined supply receivedby the air separation unit 204 remains approximately the same). If, onthe other hand the amount of compressed air extracted from the turbinecompressor 104 is decreased, the supply of compressed air furnished bythe main air compressor 202 may be increased by approximately the sameamount.

As one of ordinary skill in the art would appreciate, the determinationof compressor pressure ratio may be determined from pressuremeasurements from the inlet and exit of the turbine compressor 104,which may be taken by commercially available pressure gauges,transducers or similar devices placed at the inlet and exit of theturbine compressor 104. The measurement of flow rate through the turbinecompressor 104 may be taken by measuring the pressure drop across thecompressor bellmouth, incorporating compressor inlet flow probes or byusing other similar methods or devices. The measurement of the speed(i.e., rpm) of the turbine compressor 104 may be taken by a magneticspeed sensor, key phasor probe or other similar devices. As one ofordinary skill in the art would appreciate, the relevant compressorpressure ratio (i.e., the compressor pressure ratio that reflects either(1) the compressor pressure ratio that causes surge or (2) thecompressor pressure ratio that results in a compressor margin thatviolates the minimum compressor operating limit line 302) may bepredicted based on actual test results that are obtainable forcommercially available gas turbine engines and/or computations based onthe turbine characteristics and a given flow rate and speed.

As stated, those skilled in the art will appreciate that other controlprocesses, methods and systems may be used to vary the extraction levelso that turbine load is efficiently controlled. It should be apparentthat the foregoing relates only to the preferred embodiments of thepresent application and that numerous changes and modifications may bemade herein without departing from the spirit and scope of theapplication as defined by the following claims and the equivalentsthereof.

1. A method of protecting a turbine compressor of a gas turbine enginethat is part of an integrated gasification combined-cycle powergeneration system that includes an air separation unit, comprising thesteps of: extracting an amount of compressed air that is compressed bythe turbine compressor; supplying the extracted amount of compressed airto the air separation unit; and varying the amount of compressed airextracted from the turbine compressor based upon a desired compressorpressure ratio across the turbine compressor; wherein the step ofvarying the amount of compressed air extracted comprises measuring thepressure at an inlet and exit of the turbine compressor; determining anactual compressor pressure from the pressure measurements taken at theinlet and exit of the turbine compressor; and comparing the actualcompressor pressure ratio to the desired compressor ratio until thedesired compressor pressure ratio is reached.
 2. The method of claim 1,further comprising the step of supplying the air separation unit with asupply of compressed air from a main air compressor.
 3. The method ofclaim 2, further comprising the step of varying the amount of compressedair supplied to the air separation unit by the main air compressor basedupon the amount of compressed air extracted from the turbine compressor.4. The method of claim 3, wherein a combined supply of compressed aircomprises the amount of compressed air supplied to the air separationunit by the main air compressor and the amount of compressed airextracted from the turbine compressor; and wherein the combined supplyof compressed air comprises a supply of compressed air that satisfiesthe total supply of compressed air required by the air separation unit.5. The method of claim 2, wherein the step of varying the amount ofcompressed air supplied to the air separation unit by the main aircompressor based upon the amount of compressed air extracted from theturbine compressor comprises the step of decreasing the amount ofcompressed air supplied to the air separation unit by the main aircompressor when the amount of compressed air extracted from the turbinecompressor is increased.
 6. The method of claim 5, wherein the amount bywhich the compressed air supplied to the air separation unit by the mainair compressor is decreased comprises approximately the same amount bywhich the compressed air extracted from the turbine compressor isincreased.
 7. The method of claim 5, wherein the step of varying theamount of compressed air supplied to the air separation unit by the mainair compressor based upon the amount of compressed air extracted fromthe turbine compressor comprises the step of increasing the amount ofcompressed air supplied to the air separation unit by the main aircompressor when the amount of compressed air extracted from the turbinecompressor is decreased.
 8. The method of claim 7, wherein the amount bywhich the compressed air supplied to the air separation unit by the mainair compressor is increased comprises approximately the same amount bywhich the compressed air extracted from the turbine compressor isdecreased.
 9. The method of claim 1, wherein the desired compressorpressure ratio comprises a compressor pressure ratio that either doesnot cause the turbine compressor to surge or violate a desired minimumcompressor margin.
 10. The method of claim 9, further comprising thestep of increasing the amount of compressed air extracted from theturbine compressor when the actual compressor pressure ratio is measuredto be greater than the desired compressor pressure ratio.
 11. The methodof claim 10, further comprising the step of decreasing the amount ofcompressed air extracted from the turbine compressor when the actualcompressor pressure ratio is measured to be less than the desiredcompressor pressure ratio.
 12. A system for protecting a turbinecompressor of a gas turbine engine that is part of an integratedgasification combined-cycle power generation system that includes an airseparation unit, comprising: a turbine compressor that compresses air;means for extracting an amount of compressed air from the turbinecompressor and means for supplying the extracted amount of compressedair to the air separation unit; and means for varying the amount ofcompressed air extracted from the turbine compressor based upon adesired compressor pressure ratio across the turbine compressor; andmeans for determining an actual compressor pressure ratio across theturbine compressor; wherein the means for varying the amount ofcompressed air extracted from the turbine compressor based upon adesired compressor pressure ratio across the turbine compressorcomprises means for comparing the actual compressor pressure ratio fromthe pressure measurements taken at an inlet and exit of the turbinecompressor to the desired compressor pressure ratio across the turbinecompressor and means for varying the amount of compressed air extractedfrom the turbine compressor based on the comparison of the actualcompressor pressure ratio across the turbine compressor against thedesired compressor pressure ratio across the turbine compressor.
 13. Thesystem of claim 12, wherein the desired compressor pressure ratio acrossthe turbine compressor comprises a compressor pressure ratio that eitherdoes not cause the turbine compressor to surge or violate a desiredminimum compressor margin.
 14. The system of claim 13, wherein theamount of compressed air extracted from the turbine compressor isincreased when the actual compressor pressure ratio is measured togreater than the desired compressor pressure ratio.
 15. The method ofclaim 13, wherein the amount of compressed air extracted from theturbine compressor is decreased when the actual compressor pressureratio is measured to be less than the desired compressor pressure ratio.16. The system of claim 13, wherein the means for varying the amount ofcompressed air extracted from the turbine compressor based upon thedesired compressor pressure ratio across the turbine compressorcomprises a proportional-integral-derivative controller controlling avalve.
 17. The system of claim 12, further comprising a main aircompressor that supplies the air separation unit with a supply ofcompressed air from a main air compressor.
 18. The system of claim 17,further comprising means for varying the amount of compressed airsupplied to the air separation unit by the main air compressor; whereinthe amount of compressed air supplied to the air separation unit by themain air compressor is varied based upon the amount of compressed airextracted from the turbine compressor.
 19. The system of claim 18,wherein the amount of compressed air supplied to the air separation unitby the main air compressor is increased when the amount of compressedair extracted from the turbine compressor is decreased; and the amountof compressed air supplied to the air separation unit by the main aircompressor is decreased when the amount of compressed air extracted fromthe turbine compressor is increased.